Voters have spoken, and states are moving toward cleaner electricity. Legislatures in Hawaii and California passed mandates for 100 percent clean energy in the electricity sector, and governors in Colorado, Illinois, Nevada, New Jersey, New York, Maine, and Michigan have all made similar 100 percent clean energy promises in recent months. These ambitious targets will require large-scale integration of wind and solar energy, which can be unpredictable and intermittently available. Cost-effective energy storage solutions can play a leading role to provide clean, reliable electricity—even when the sun isn’t shining and wind isn’t blowing.

Energy storage systems—ranging from lithium-ion (Li-ion) batteries to hydroelectric dams—can provide a wide array of valuable grid services. Their ability to bank excess energy for use at a later date makes them particularly well-suited to address the intermittency challenge of wind and solar. In some cases, energy storage systems are also already cost-competitive with natural gas plants.

However, in order to reach ambitious clean energy targets, we’ll likely need to close a large energy storage gap. One recent estimate suggests approximately 10,000 Gigawatt hours (GWh) of energy storage may be needed to support a two-thirds renewables domestic electricity mix. In our policy brief, we estimate the United States currently has no more than 10 percent of this utility-scale energy storage capacity available; the actual quantity is likely much lower. Developing vast levels of energy storage will likely be an important factor toward integrating a greater share of renewables into the energy mix. Smart policy design can help drive energy storage prices even further below current historic lows, while ensuring these technologies are procured cost-effectively.

A path forward: using reverse auctions to scale energy storage

Reverse auctions have already helped scale renewables and, when designed well, may also be an effective tool when applied to energy storage. In a reverse auction, multiple sellers submit bids to a single buyer for the right to provide a good or service. In the case of renewables, developers bid to provide a portion of capacity desired by the buyer, typically a utility. This policy tool is gaining in popularity, because, if designed well, it can drive down bid prices and ensure reliable procurement. Globally, the share of renewables capacity procured through reverse auctions is expected to grow from 20 percent in 2016 to more than 50 percent in 2022. It seems likely that auction-induced competition has triggered a fall in renewable prices that some are calling the “Auctions Revolution.”

While examples in Colorado and Hawaii suggest reverse auctions can be effective in procuring energy storage, there’s little guidance on tailoring them for that purpose. We offer five recommendations:

1: Encourage a Large Number of Auction Participants

The more developers bidding into an auction, the fiercer the competition. How policymakers approach this depends on their end goal. In a 2016 Chilean auction, bidding was open to solar and coal developers, and policymakers were pleased when solar developers offered cheaper bids on a dollar per megawatt-hour basis than coal developers. Another approach: signaling consistent demand through auction schedules. Participation in South African renewable auctions increased after auction organizers took steps to give advance notice and instructions for future regular auctions.

2: Limit the Amount of Auctioned Capacity

If competition still seems tepid, auctioneers can always scale down the amount of capacity auctioned. As witnessed in a South African renewable auction, bidders respond to a supply squeeze by decreasing their bid prices.

3: Leverage Policy Frameworks and Market Structures

Auctions don’t exist in a vacuum. Renewable auctions benefit tremendously from existing market structures and companion policies. Where applicable, auction design should consider the multiple grid services energy storage systems can offer. Even if an auction is only focused on energy arbitrage, it should not preclude storage developers from participating in multiple markets (e.g. frequency regulation), as this may help bidders reduce their bid prices.

4: Earmark a Portion of Auctioned Capacity for Less-mature Technologies

A major criticism of early auctions is that they unintentionally favored the same large players and mature technologies. Policymakers shouldn’t forget that energy storage includes several technological options; they can design auctions to address this by separating procurement for more advanced technologies (Li-ion, for example) from newer technologies (zinc air batteries).

5: Penalize delivery failures without damaging competition

Developers should be incentivized to bid their cheapest possible price, but poor auction design can trigger a race to the bottom with ever more unrealistic bid prices. This is especially true if developers don’t believe they will be punished for delivery failures or poor quality projects. Already, some contract terms for energy storage by auctions include penalties if the developer cannot deliver its promised grid service.

Decarbonizing our energy supply isn’t an easy task. Reverse auctions stand out as a possible tool to quickly and cost-effectively increase our energy storage capacity, which will help integrate intermittent renewables. If this market-based mechanism can be tailored to suit energy storage systems’ capabilities (e.g. offering multiple grid services), it could help shift us to a future where we have access to clean energy at any time of day and year.

After a nearly 20-year upward trend, U.S. CO2 emissions from energy took a sharp and unexpected turn downwards in 2007. By 2013, the country’s annual CO2 emissions had decreased by 11% – a decline not witnessed since the 1979 oil crisis.

Experts have generally attributed this decrease to the economic recession, and to a huge surge in cheap natural gas displacing coal in the U.S. energy mix. But those same experts mostly overlooked another key factor: the parallel rise in renewable energy production from sources like wind and solar, which expanded substantially over the same 2007-2013 timeframe.

Between 2007 and 2013, wind generated electricity grew almost five-fold to 168 TWh and utility-scale solar from 0.6 TWh to 8.7 TWh. During the same period, bioenergy production grew 39 percent to 4,800 trillion BTUs.

Decomposition analysis is an established method which enables us to separate different factors of influence on total CO2-emissions and identify the contribution of each to the observed decrease. The factors considered here are total energy demand, the share of gas in the fossil fuel mix (capturing the switch from coal and petroleum to gas), and the share of renewables and nuclear energy in total energy production.

Introducing a new approach for separately quantifying the contributions from renewables, we find that renewables played a crucial role in driving U.S. energy CO­2 emissions down between 2007 and 2013 – something which has previously largely gone unrecognized.

According to our index decomposition analysis, of the total 640 million metric ton (Mt) decrease (11%) during that period two-thirds resulted from changes in the composition of the U.S. energy mix (with the remaining third due to a reduction in primary energy demand). Of that, renewables contributed roughly 200 Mt reductions, about a third of the total drop in energy CO2 emissions. That’s about the same as the contribution of the coal and petroleum-to-gas switch (215 Mt). Conversely, increases in nuclear generation contributed a relatively minor 35 Mt.

While the significant role of renewables in reducing CO2 emissions does not diminish the contribution of the switch to natural gas, it is important to note that the climate benefits of switching from coal and petroleum to gas are undermined by the presence of methane leakage along the natural gas supply chain, the extent of which is likely underestimated in national greenhouse gas (GHG) emissions inventories.

Methane, of course, is a powerful greenhouse gas. Methane leakage from increased natural gas use could have wiped out up to 30% of the short-term GHG benefit (on a CO2-equivalent basis) calculated in this paper of switching from coal and petroleum to natural gas. For the natural gas industry to truly sustain the claim that it has made a positive contribution to reducing the country’s carbon footprint, the methane emissions associated with natural gas must be substantially reduced.

These results show that past incentives to support the expansion of renewable energy have been successful in reducing the country’s emissions, and that decreasing costs for renewable energy offers some hope for continued progress even despite the current administration’s refusal to address climate change.

Such progress, however, will never be sufficient without ambitious climate and clean energy policies- whether at the federal or at the state level – that can drive further emission reductions.

New England natural gas and electricity prices have undergone dramatic spikes in recent years, spurring talk about the need for a costly new pipeline to meet the region’s needs as demand for gas seemed ready to overtake suppliers’ available capacity to deliver it. For example, during the polar vortex of 2013-14, the gas price at New England’s main gas trading hub regularly exceeded $20/MMBtu (million British Thermal Units, the measure commonly used in the gas industry) and reached a record high of $78/MMBtu on January 22, 2014, compared to the annual average of $5.50/MMBtu.

In an efficient market, we would indeed expect prices to be high during events like the polar vortex. We would also expect pipelines delivering gas to regions like the Boston area – in this case the Algonquin Gas Transmission (AGT) pipeline – to be fully utilized. But this is not what we observed when we analyzed the scheduling patterns on the AGT pipeline from 2013 to 2016.

What 8 million data points told us about artificial shortages

Our research group spent 18 months looking at eight million data points covering the three-year period from mid-2013 to mid-2016. We discovered that during this period, a handful of New England gas utilities owned by two large energy companies routinely scheduled large deliveries, then cancelled orders at the last minute. These scheduling practices created an artificial shortage when in fact there was far more pipeline capacity on the system than it appeared.

As a result, we estimate that New England electricity customers paid $3.6 billion more over this period than they would have if the unused pipeline capacity had been available to deliver gas for electricity generation (for more information on how we calculated this number, visit our methodology page). As for the need for a new pipeline, our analysis shows that energy prices over this period were inflated, which means they should not be used to assess how much, if any, additional pipeline capacity is needed. Both conclusions illustrate why it’s so important (and how valuable it could be) to fix the interface between the gas and electric markets.

Why unused pipeline capacity impacts electricity prices

Although it was natural gas that was supposedly in short supply over this period, electricity prices also experienced large price spikes. That’s due to the way electricity prices are set, and the fact that much of the electricity in New England, as in much of the country, is increasingly generated using natural gas.

About half of the electricity traded in New England’s wholesale electricity market, ISO New England (ISO-NE), comes from gas-fired generators. For any given hour, the wholesale electricity price for all generators in this market is determined by the last (highest) bid needed to meet customer demand (or “clear the market”). This market clearing price is typically (75 percent of the time) set by a natural gas plant, which means their cost for gas and pipeline transportation tends to drive the price of electricity. That cost is largely determined by the spot price of natural gas at Algonquin Citygate, New England’s main gas trading hub, served by the Algonquin Pipeline.

The figure below shows a stylized generation supply curve for ISO-NE. The lower cost resources to the left (typically solar, wind and hydro) are generally used before the higher cost plants to the right (coal, gas, petroleum). The plants situated where demand meets the supply curve set the overall market price in any given hour (bids are submitted a day ahead of time in the day ahead market). This is typically one of the natural gas plants represented by the red dots on the middle part of the curve. A higher spot price for natural gas increases the marginal cost of gas-fired generators, shifting the generation supply curve up as seen in the second panel. This translates into a higher marginal cost of meeting a given level of electricity demand and thus a higher wholesale electricity price P*.

Stylized generation supply curve for ISO-NE.

What price do electric generators pay for gas? The secondary market for natural gas

In New England, as in many other markets, gas-fired electricity generators generally procure gas from a secondary market, where sellers are usually natural gas utilities that purchase long-term contracts at regulated prices directly from the pipeline company. The secondary market exists because these long-term contracts allow contract holders to sell any unused capacity at unregulated prices to gas-fired generators or others.

Generators buying in the secondary market for gas do so because they have decided it is more cost-effective to procure natural gas transportation that way than to grapple with rigid, long-term contracts for pipeline capacity that don’t fit their highly variable needs.

While the amount of pipeline capacity available to deliver natural gas to New England is fixed, demand for gas fluctuates significantly with external factors such as temperature, as seen by the price spikes experienced during the polar vortex

On days like these, holders of long-term contracts can pocket the difference between the price that buyers in the secondary market are willing to pay for gas deliveries, as indicated by the Algonquin Citygate spot price, and the regulated price they themselves pay the pipeline for that same capacity. In the case of utilities, revenues from such sales are typically to a large extent refunded back to the ratepayers that paid for those long-term contracts in the first place.

How could pipeline capacity go unused during the polar vortex?

We see four local gas utilities (two owned by Eversource, two by Avangrid) that scheduled far more pipeline capacity the day before gas delivery than they ended up using the next day. Repeatedly, these companies downscheduled their orders only at the end of the gas delivery day–too late for that unused capacity to be made available to the secondary market.

The threshold at which last-minute down-scheduling of gas orders impacts gas and electric prices varies depending on daily demand. As a proxy, we looked at how far the scheduling patterns at delivery “nodes” on the pipeline operated by Eversource and Avangrid-owned utilities deviated from the overall system average.

On 434 days during the study period, at least one Eversource node made downward scheduling changes more than two standard deviations larger than the average scheduling change made by all firms on the pipeline.

On 351 days, at least one Eversource location had a schedule change more than three standard deviations larger than the average.

The Eversource utilities primarily made large downscheduling changes on cold days, while Avangrid made large scheduling cuts far more often.

On 1043 days, at least one Avangrid location made downward scheduling change more than two standard deviations larger than the average.

On 1031 days, at least one Avangrid location made a downward change more than three standard deviations larger than the average.

Total unused capacity exceeded 100,000 MMBtu on 37 days in the three-year period we looked at, which is roughly 7% of the pipeline’s total daily capacity and 28% of the typical total daily supply to gas-fired generators. That these large amounts of downscheduled pipeline capacity were not made available to New England’s gas-fired generators raised both the gas price for generators as well as the price of electricity for New England’s electricity customers. We estimate that unused pipeline capacity increased average gas and electricity prices by 38% and 20%, respectively, over the three-year period we study.

While this behavior may have been within the companies’ contractual rights, the significant impacts in both the gas and electricity markets show the need to consider improvements to market design and regulation. The gas transportation market must become more transparent and flexible to better ensure that existing pipeline capacity is optimally utilized and that unbiased price signals in both the gas and electricity markets lead to cost-efficient investment in energy infrastructure.

New Risky Business Report Finds Transitioning to a Clean Energy Economy is both Technologically and Economically Feasible

In the first Risky Business report, a bi-partisan group of experts focused on the economic impacts of climate change at the country, state and regional levels and made the case that in spite of all that we do understand about the science and dangers of climate change, the uncertainty of what we don’t know could present an even more devastating future for the planet and our economy.

The latest report from the Risky Business Project, co-chaired by Michael R. Bloomberg, Henry M. Paulson, Jr., and Thomas F. Steyer, examines how best to tackle the risks posed by climate change and transition to a clean energy economy by 2050, without relying on unprecedented spending or unimagined technology. The report focuses on one pathway that will allow us to reduce carbon emissions by 80 percent by 2050 through the following three shifts:

1. Electrify the economy, replacing the dependence on fossil fuels in the heating and cooling of buildings, vehicles and other sectors. Under the report’s scenario, this would require the share of electricity as a portion of total energy use to more than double, from 23 to 51 percent. 2. Use a mix of low- to zero-carbon fuels to generate electricity. Declining costs for renewable technologies contribute in making this both technologically and economically feasible. 3. Become more energy efficient by lowering the intensity of energy used per unit of GDP by about two thirds.

New Investments Will Yield Cost Savings

Of course, there would be costs associated with achieving the dramatic emissions reductions, but the authors argue that these costs are warranted. The report concludes that substantial upfront capital investments would be offset by lower long-term fuel spending. And even though costs would grow from $220 billion per year in 2020 to $360 billion per year in 2050, they are still likely far less than the costs of unmitigated climate change or the projected spending on fossil fuels. They’re also comparable in scale to recent investments that transformed the American economy. Take the computer and software industry, which saw investments more than double from $33 billion in 1980 to $73 billion in 1985. And those outlays continued to grow exponentially—annual investments topped $400 billion in 2015. All told, the United States has invested $6 trillion in computers and software over the last 20 years.

This shift would also likely boost manufacturing and construction in the United States, and stimulate innovation and new markets. Finally, fewer dollars would go overseas to foreign oil producers, and instead stay in the U.S. economy.

The Impact on American Jobs

The authors also foresee an impact to the U.S. job market. On the plus side, they predict as many as 800,000 new construction, operation and maintenance jobs by 2050 would be required to help retrofit homes with more efficient heating and cooling systems as well as the construction, operation and maintenance of power plants. However, job losses in the coal mining and oil and gas sectors, mainly concentrated in the Southern and Mountain states, could offset these employment gains. As we continue to grow a cleaner-energy economy, it will be essential to help workers transition from high-carbon to clean jobs and provide them with the training and education to do so.

A Call for Political and Private Sector Leadership

Such a radical shift won’t be easy, and both business and policy makers will need to lead the transition to ensure its success. First and foremost, the report asserts that the U.S. government will need to create the right incentives. This will be especially important if fossil fuel prices drop, which could result in increased consumption. Lawmakers would also need to wean industry and individuals off of subsidies that make high-carbon and high-risk activities cheap and easy while removing regulatory and financial barriers to clean-energy projects. They will also need to help those Americans negatively impacted by the transition as well as those who are most vulnerable and less resilient to physical and economic climate impacts.

To be sure, this kind of transformation and innovation isn’t easy, but the United States has sparked technological revolutions before that have helped transform our economy—from automobiles to air travel to computer software, and doing so has required collaboration between industry and policymakers.

We are at a critical point in time—we can either accelerate our current path and invest in a clean energy future or succumb to rhetoric that forces us backwards. If we choose to electrify our economy, reduce our reliance on dirty fuels and become more energy efficient, we will not only be at the forefront of the next technological revolution, but we’ll also help lead the world in ensuring a better future for our planet.

New York is preparing for a future in which clean, distributed energy resources – such as energy efficiency, electric vehicles, rooftop solar panels, and other types of local, on-site power generation – form an integral part of a more decentralized electric grid. This is the future the New York Public Service Commission (PSC) wants to see realized through its signature initiative, Reforming the Energy Vision (REV).

This vision means the role of the customer is changing: from recipient to both user and provider of electricity and other grid services. By investing in clean, distributed energy resources, customers can make the electric system more efficient and contribute to a cleaner environment, while gaining greater control over their energy bills. Read More »

Electricity markets around the world are transforming from a model where electricity flows one way (from electricity-generating power plants to the customer) to one where customers actively participate as providers of electric services. But to speed this transformation and maximize its environmental and cost benefits, we need to understand how customer actions affect the three distinct parts of our electric system: generation, transmission, and distribution. Read More »